In the recovery of oil from a subterranean oil-bearing geological formation only a limited amount of the oil in place is recoverable by use of primary and secondary recovery processes. Primary production techniques (i.e. use of pressure in the formation) lead to the recovery of about 15% to 20% of the original oil in place (OOIP). Secondary water flooding techniques can recovery additional oil, leading to recovery of about 40% of the original oil in place. Several tertiary or enhanced oil recovery processes have therefore been developed to additionally recover some or all of the remaining oil.
Such tertiary processes include thermal processes (e.g., thermal injection), exemplary of which are steam flooding and in-situ combustion, chemical flooding techniques, and gaseous displacement fluid recovery methods (e.g., gas injection), which can be operated under either miscible or non-miscible conditions. The gases commonly utilized in these systems are commonly referred to as non-condensable gases and can include both natural gas and produced gas such as steam, carbon dioxide, nitrogen, methane, ethane, or mixtures of these along with other hydrocarbon homologues.
However, there are problems associated with the use of gaseous displacement fluid recovery methods. Fingering of the gas phase into the oil, leading to loss of the uniform displacement front, may take place, because of the higher mobility of the displacing gas.
A further problem is gravity override which is promoted by the viscosity and/or density difference between the gas and oil phases. Sweep efficiency, and contact between the injected fluid or gas and the oil in the reservoir, are reduced because of these problems, hence, the incremental recovery will as a result also be reduced. Reservoir heterogeneity will further increase these problems by promoting channelling, thereby further reducing the sweep efficiency.
In oil recovery operations, it is common practice to inject gaseous foams (gas in water, G/W) into the reservoir or subterranean oil- or gas-bearing geological formation to aid in the displacement and recovery of oil from the formation. Using surfactants and liquids, such as water based solutions, it is possible to create G/W foams for oil recovery operations. As these foams are injected into the reservoir, they will reduce the effects of (1) the poor mobility ratio between injected and reservoir fluids, (2) other causes of poor areal sweep efficiency, (3) poor vertical sweep efficiency, (4) non-oil saturated or thief zones, and (5) reservoir heterogeneities. Foams will assist in controlling the mobility of the gas through the formation, which is one approach for pushing and extracting the oil via enhanced technologies, and this will lead to the efficient extraction of more oil. Select foam products will also function as blocking and diverting agents, assuring that fluid which is extracting and emulsifying oil, flows through the desired parts of the formation and is not lost due to channelling into undesired areas. The foam is either generated in-situ by injecting the ingredients into the geological formation or is formed at the surface and injected as a foam per se. One favourable process involves injecting the surfactant solution and, once it is in position within the reservoir, then injecting the gas to form the foam.
The use of foams for mobility control has been well documented and described in the patent literature. Indeed, the current art details the usage of many types of surfactants as foaming agents for oil recovery operations. Some of the types of surfactants detailed in the art as generating high and long lasting foam include surfactants that have anionic, cationic, amphoteric, zwitterionic, and nonionic groups as hydrophilic groups, in addition to hydrophobic groups. Specific chemical classes include alkyl sulfonates, alkylaryl sulfonates, alkyl diphenyl ether disulfonates, arylsulfonates, alpha-olefin sulfonates, petroleum sulfonates, alkyl sulfates, alkylether sulfates, alkylarylether sulfates, betaines, ethoxylated and propoxylated alcohols, fluorosurfactants, sorbitan and ethoxylated sorbitan esters, and blends of these materials.
For example, an early document describing use of foams for mobility control is U.S. Pat. No. 2,623,596 A, where carbon dioxide is used as a miscible solvent gas. Numerous patent documents published more recently relate to improvements of this technology, such as U.S. Pat. No. 4,088,190 A, where injection of a fluid foam is described, made from carbon dioxide, water, and a foaming agent which is a straight-chain alkyl sulfoacetate. In U.S. Pat. Nos. 4,836,281 A and 4,923,009 A, fluorocarbon surfactants are used in an enhanced oil recovery process, as foaming agent and surface tension depressant. Foams made from inert gases and a fluorocarbon surfactant solution whereto amphoteric or anionic surfactants are admixed, have been known from U.S. Pat. No. 5,074,358 A. The use of mixtures of alkylated diphenyl oxide and at least one amphoteric surfactant as foaming agents has been disclosed in U.S. Pat. No. 5,203,411 A. A foam-forming composition is described in U.S. Pat. No. 5,358,045 A, which comprises water, a foaming agent which is an alpha-olefin sulfonate having from ten to sixteen carbon atoms, and a solubilising compound which is an alkali or earth alkali salt of a diphenyl ether disulfonic acid having alkyl substituents of from six to sixteen carbon atoms in one or both para positions with regard to the ether oxygen atom. A foam generated from a non-condensible gas, water, and a non-ionic surfactant is disclosed in U.S. Pat. No. 5,363,915 A. Increased foam quality and resistance to hydrocarbon defoaming has been found in U.S. Pat. No. 5,614,473 A when using imidazoline-based amphoacetates of high purity as amphiphilic surfactants. Additional presence of hydrocolloids such as xanthan gum is mentioned. In U.S. Pat. No. 6,113,809 A, generation of a sustainable foam is described using surfactants derived from imidazoline having a structureR—CO—NH—CH2—CH2—N[(CH2)nX]—CH2—CO—OMwith R being an aliphatic radical containing from five to nineteen carbon atoms per molecule, X being OH or NH2, n being an integer of from 2 to 4, and M being a metal, where the surfactants must be in a pure state, i.e. substantially free from starting products. Mixtures of surfactants and co-surfactants have been described in U.S. Pat. No. 7,842,650 B2, where one of the constituents is broadly selected from the group of sulfates, sulfonates, phosphates, carboxylates, sulfo-succinates, betaines, quaternary ammonium salts, amine oxides, amine ethoxylates, amide ethoxylates, acid ethoxylates, alkyl glucosides, ethylene oxide-propylene oxide block copolymers, and long-chain fatty alcohol ethoxylates; and the other constituent is at least one cosurfactant different therefrom, of the structure x-y or x-y-z, in which x is a surfactant alcohol having six to twelve carbon atoms, y is an alkylene oxide block and z is a terminal group. Foam-forming compositions comprising mixtures of at least one non-ionic surfactant and at least one ionic surfactant which latter include anionic, cationic, and zwitterionic or amphoteric surfactants have been disclosed in U.S. Pat. No. 7,422,064 B1.
It is well known that the presence of hydrocarbon oils present in the geological formation can contribute to reducing or limiting the stability of the foam formed from aqueous solutions. Therefore, foaming efficiency is an important factor when foams are used to recover hydrocarbons from subterranean strata. Foam stability can also be reduced when the aqueous solution contains dissolved salts such as those that are commonly found in the geologic formations from which oil and natural gas are to be recovered. These salts typically contain cations such as sodium, potassium, lithium, calcium, magnesium and anions such as chloride, sulfate, carbonate, bicarbonate, fluoride etc. The most common types of aqueous media for the gas/water foams include seawater, seawater/diesel and brine solutions of various concentrations. Foam stability can further be reduced when the temperature of the oil or natural gas bearing formation is high. Typically, the higher the temperature the poorer is the stability of the foam. In many cases the temperature of the formation can be elevated, such as at least 30° C., 40° C., 50° C., 60° C., or even higher, such as 90° C. or 95° C.
Additionally, one major issue with the selection of surfactants for oil and gas recovery applications is that the properties of the oil and conditions of the reservoir can greatly influence surfactant selection and performance. In selecting a surfactant to serve as a foaming agent one must examine its performance in formulations and environments that will approximate the end use application. Selection of a surfactant foaming agent is influenced by the surfactant chemistry, composition of the brine and gas, nature of the porous medium, foam quality, texture and flow rate and temperature and pressure. Ideally, one is looking for a surfactant that exhibits good solubility in the brine at surface and reservoir conditions, has appropriate thermal stability under reservoir conditions, has a low adsorption onto the reservoir rock and does not partition to the crude oil. The surfactant should also exhibit a strong ability to promote and stabilise the foam, reduce gas mobility into the porous media and assure that the foam does not readily interact with crude oil in the porous media.
Surfactants for enhanced oil recovery applications that offer improved foaming performance in multiple (and diverse) aqueous media and that have a high tolerance to elevated temperatures, dissolved salts, and/or the presence of hydrocarbon oil, and which would thus provide for a high foaming efficiency, and lead to stable foams would be a useful advance in the art and could find rapid acceptance in the industry.